1. Field of the Invention
This invention relates broadly to estimating residual carbon dioxide (CO2) saturation in aquifers. More particularly, this invention relates to estimating residual CO2 saturation (Scr) from nuclear magnetic resonance (NMR) measurements obtained by a logging tool.
2. State of the Art
Elevated carbon dioxide concentration in the atmosphere is widely accepted as a contributor to global climate change. Carbon capture and sequestration (CCS) is one of the pursued technologies to reduce atmospheric accumulation of CO2.
Suitability of a carbon dioxide geological storage site is commonly characterized by three metrics: capacity, infectivity and containment. Evaluation of these three performance measures at early stages of a CO2 storage project relies largely upon seismic and well characterization, reservoir modeling and simulation. Petrophysical properties such as porosity, permeability and residual saturation of aqueous and CO2-rich phases describe the target formation zone, and serve as inputs for simulation models. The estimates for these properties are usually inferred from wireline measurements. Porosity is usually estimated based on neutron scattering and density measurements, while permeability is commonly inferred from NMR measurements. See, Timur, A. “Pulsed Nuclear Magnetic Resonance Studies of Porosity, Moveable Fluid, and Permeability of Sandstones,” Journal of Petroleum Technology, 21:775-786 (1969); Kenyon, W. E., et al., “A Three-part Study of NMR Longitudinal Relaxation Properties of Water-Saturated Sandstones,” SPE Formation Evaluation, 3:622-636 (1988); Kenyon, W. E., et al., “Erratum,” SPE Formation Evaluation, 4:8 (1989). In practice, NMR based inference is not absolute and requires zonal calibration. Methods for evaluating surface relaxivity from stationary formation tests to calibrate NMR logs are proposed in U.S. Pat. No. 7,221,158 to Ramakrishnan which is hereby incorporated by reference herein in its entirety.
In geological storage, brine displaced by CO2 counter-imbibes to form trapped or residual CO2. This refers to the part of the CO2-rich phase disconnected from the rest of the phase exhibiting pressure continuity. Unlike oil wells, in geological storage sites, CO2 is not present during drilling. Therefore drilling fluid filtrate invasion consists of a single phase displacement, and an estimate of Scr cannot be obtained. While estimations of residual saturations can be obtained as part of an advanced core analysis which is conducted in the lab through displacement experiments, laboratory methods are laborious and are available only at formation locations and depths which have been subjected to coring. As will be appreciated by those skilled in the art, formation coring is slow and expensive, and provides information for only the specific coring locations. Given the desire to rapidly develop geological CO2 storage worldwide, reliance on coring is not a suitable option.